Occidental Petroleum Corp (NYSE: OXY) company reported third-quarter core income of $2.6 billion, up from $1.8 billion a year ago and flat with the prior quarter. Although the company’s price realizations on oil declined 6 percent from the second quarter to about $97 per barrel and NGL prices fell 3 percent to about $56 per barrel, a 2 percent sequential increase in overall production offset this weakness. About 60 percent of the company’s oil output tracks the price of Brent crude oil, while 40 percent of its production is indexed to the price of West Texas Intermediate crude oil.
Occidental Petroleum’s domestic exploration and production operations were the star of the third quarter, flowing a record high of 436,000 barrels of oil equivalent per day--a 15 percent uptick from year-ago levels. Management expects its US assets to yield between 3,000 and 4,000 additional barrels of oil equivalent per day during each month of the fourth quarter.
The company’s US upstream operations offer plenty of upside. The leading producer of hydrocarbons in Texas, Occidental Petroleum’s operations within the state are centered in the Permian Basin, an area with a long production history that’s been revitalized by advances in squeezing oil from mature wells. Management estimates that the company is responsible for roughly 20 percent of the oil produced in the Permian.
Carbon dioxide (CO2) injections account for about 60 percent of the company’s Permian output, while 30 percent is generated by water flooding. Both technologies facilitate production in mature fields by artificially increasing well pressure. Primary drilling and production account for just 10 percent of output, though Occidental Petroleum’s acreage contains over 2,000 prospective drilling sites. The company also pursues a substantial drilling program in the promising Wolfberry and Bone Springs areas.
But its most exciting domestic opportunity is in California, where the it has a growing inventory of more than 3,700 drilling locations, the majority of which are prospective for oil and located in areas that are held by production. Few investors would regard California as a huge energy producer--probably because the population boom of the 1940s and huge oil discoveries in the Middle East distracted many producers from developing the area.
Beginning in 1998 with the acquisition of its Elk Hills acreage from the government, Occidental’s geologists have made some unprecedented discoveries in the state, including a massive conventional find in Kern Country that management estimates could contain upward of 175 to 250 million barrels of oil equivalent.
And that says nothing about the approximately 870,000 acres the company holds in prospective shale plays. A long history of seismic activity in the area has essentially pre-fractured the field, substantially lowering costs. The company has identified 520 geologically viable shale drilling locations in California, roughly 250 of which are outside Elk Hills and Kern County. In 2011 management expects to drill 154 shale wells outside Elk Hills proper--47 more wells than the company projected at the beginning of the year.
The average shale well outside Elk Hills yields an initial production rate of between 300 and 400 barrels of oil equivalent per day and costs about $3.5 million. Lower-than-expected costs explain why the company exceeded its initial drilling guidance to such an extent.
Occidental Petroleum’s 13-rig development program in North Dakota’s Williston Basin continues apace, and management expected the play to yield up to 10,000 barrels of oil equivalent per day in the fourth quarter. The company will continue to add acreage through bolt-on transactions but won’t pursue a whole-company takeover.
During Occidental Petroleum’s conference call to discuss third-quarter earnings, CEO Stephen Chazen provided little insight into the company’s plans for 2012--save that the company plans to reduce the amount of capital allocated to natural gas-only fields in the US. Chazen lamented, “[It] just drives you nuts to give it [natural gas] away for $3.50 per million British thermal units.”
Temporary project delays and disruptions in the Middle East and Colombia. weighed on the company’s international oil and gas output during the third quarter. If these assets had produced at their expected capacity, Occidental Petroleum’s total output would have increased by at least another 10,000 barrels of oil equivalent per day.
Management continues to leverage the firm’s experience in maximizing production from mature fields to win business in the Middle East. The company inked a 30-year contract with the Abu Dhabi National Oil Company to participate in the development of the Shah natural gas field, one of the region’s largest. The company will have a 40 percent stake in the play, and management expects capital expenditures of roughly $4 billion. But the field won’t enter production until 2014.
Over the long haul, Occidental Petroleum’s expertise in maximizing production from onshore fields should enable it to grow its business in the Middle East. Meanwhile, the Permian Basin provides a solid production base and plenty of opportunity to expand through bolt-on acquisitions.